This section is intended to introduce the reader to various aspects of art, which may be associated with embodiments of the present invention. This discussion is believed to be helpful in providing the reader with information to facilitate a better understanding of particular techniques of the present invention. Accordingly, it should be understood that these statements are to be read in this light, and not necessarily as admissions of prior art.
The production of hydrocarbons, such as oil and gas, has been performed for numerous years. To produce these hydrocarbons, a production system may utilize various devices for specific tasks within a well. Typically, these devices are placed into a wellbore completed in either cased-hole or open-hole completion. In cased-hole completions, wellbore casing is placed in the wellbore and perforations are made through the casing into subterranean formations to provide a flow path for formation fluids, such as hydrocarbons, into the wellbore. Alternatively, in open-hole completions, a production string is positioned inside the wellbore without wellbore casing. The formation fluids flow through the annulus between the subsurface formation and the production string to enter the production string.
When producing hydrocarbons from subterranean formations, especially poorly consolidated formations or formations weakened by increasing downhole stress due to wellbore excavation and/or fluids withdrawal, it is possible to produce undesirable materials, such as solid materials (for example, sand) and fluids other than the desired hydrocarbons (for example, water). In some cases, formations may produce hydrocarbons without sand until the onset of water production from the formations. With the onset of water, these formations collapse or fail due to increased drag forces (water generally has higher viscosity than oil or gas) and/or dissolution of material holding sand grains together. Additionally or alternatively, water is often produced with hydrocarbon due to various causes including coning (rise of near-well hydrocarbon-water contact), casing leaks, poor cementing, high permeability streaks, natural fractures, and fingering from injection wells.
The sand/solids and water production can result in a number of problems. These problems include productivity loss, equipment damage, and/or increased treating, handling and disposal costs. For example, the sand/solids production may plug or restrict flow paths resulting in reduced productivity. The sand/solids production may also cause severe erosion resulting in damage to wellbore equipment, which may create well control problems. When produced to the surface, the sand is removed from the flow stream and has to be disposed of properly, which increases the operating costs of the well.
Water production also reduces productivity. For instance, because water is heavier than hydrocarbon fluids, it takes more pressure to move it up and out of the well. That is, the more water produced, the less pressure available to move the hydrocarbons, such as oil. In addition, water is corrosive and may cause severe equipment damage if not properly treated. Similar to the sand, the water also has to be removed from the flow stream and disposed of properly. Any one or more of these consequences of water production increases the cost of operating the well.
The sand/solids and water production may be further compounded with wells that have a number of different completion intervals in which the formation strength may vary from interval to interval. Because the evaluation of formation strength is complicated, the ability to predict the timing of the onset of sand and/or water is limited. In many situations reservoirs are commingled to minimize investment risk and maximize economic benefit. In particular, wells having different intervals and marginal reserves may be commingled to reduce economic risk. One of the risks in these applications is that sand failure and/or water breakthrough in any one of the intervals threatens the remaining reserves in the other intervals of the completion.
Conventional methods for preventing or mitigating water production include selective perforation, zone isolation, inflow control system, resin treatment, downhole separation, and surface-controlled downhole valves. Preventive methods such as selective perforation, zone isolation, inflow control systems, and surface-controlled downhole valves are applied at pre-determined, high water production potential locations along the wellbore (or low potential in the case of selective perforation). Due to the uncertainty in identifying the timing, location and magnitude of potential water production, the results have been often unsatisfactory.
The historical water shut-off method is injecting chemicals into the water production intervals to plug the formation matrix. The chemicals include cement and resins, which are gelled or solidified with temperature and time. These methods have long been challenged by gelation kinetics, placement, and long-term stability. Other common methods include the use of packer or cement plugs to isolate water production zones. Mechanical sleeve or casing cladding has also been used to isolate the water inflow. The technique involves positioning either a thermally inflatable patch or a mechanically expandable patch against the desired cladding length. Good planning, design, and execution are required for job success.
Downhole separation methods rely upon the installation of a hydrocyclone and pump in the borehole to inject separated water to different subterranean horizons. The increasing completion complexity can be readily appreciated. To further complicate these efforts, the sizing of a suitable separator is difficult due to the changing incoming water rate during the well lifetime.
In recent efforts to address the problems presented by water production, polymers have been used to modify the permeability of the tubes and pipes associated with the production string. For example, some efforts include injecting polymers from the surface to target areas of water production and impede the water flow. The injected polymers have to be carefully selected and carefully injected for any chance of success in this implementation. Processes such as this requiring on-site intervention are generally more economically and technologically challenging.
As a variation on the efforts to use polymers to address water production, others have attempted to coat screens, such as conventional sand screens, with swellable materials designed to seal flow paths through swelling. These swellable materials are conventionally a polymeric material or other material coated with a polymer that reacts upon contact with water to swell. Past efforts have attempted to design screens having sufficient spacing to allow fluid flow under desired conditions and to form an adequate seal under undesired conditions. For example, the selection of the swellable materials and the choice of how much swellable material to incorporate in the screen required careful design to ensure the polymer or other material would react when desired and in the manner intended. Other efforts have disposed fixed swelling members in association with a conventional sand screen attempting to cause the swelling members to swell around the sand screen when water is produced. However, here again, the efforts have relied upon costly swellable materials that require careful selection. For example, when polymeric swelling materials are used, care must be taken to ensure that the polymer does not react with other chemicals that may be in the produced fluids, either to swell or in some other manner.
While typical sand and water control, remote control technologies, and interventions may be utilized, these approaches often drive the cost for marginal reserves beyond the economic limit. As such, a simple, lower cost alternative may be beneficial to lower the economic threshold for marginal reserves and to improve the economic return for certain larger reserve applications. Accordingly, the need exists for a well completion apparatus that provides a mechanism for managing the production of water within a wellbore, while staying within dimensional limitations of a wellbore.
Other related material may be found in at least U.S. Pat. No. 6,913,081; U.S. Pat. No. 6,767,869; U.S. Pat. No. 6,672,385; U.S. Pat. No. 6,660,694; U.S. Pat. No. 6,516,885; U.S. Pat. No. 6,109,350; U.S. Pat. No. 5,435,389; U.S. Pat. No. 5,209,296; U.S. Pat. No. 5,222,556; U.S. Pat. No. 5,222,557; U.S. Pat. No. 5,211,235; U.S. Pat. No. 5,101,901; and U.S. Patent Application Publication No. 2004/0177957. Additional related material may be found in U.S. Pat. No. 5,722,490; U.S. Pat. No. 6,125,932; U.S. Pat. No. 4,064,938; U.S. Pat. No. 5,355,949; U.S. Pat. No. 5,896,928; U.S. Pat. No. 6,622,794; U.S. Pat. No. 6,619,397; International Patent Publication WO/2007/094897; and International Patent Application No. PCT/US2004/01599. Further, additional information may also be found in Penberthy & Shaughnessy, SPE Monograph Series—“Sand Control”, ISBN 1-55563-041-3 (2002); Bennett et al., “Design Methodology for Selection of Horizontal Open-Hole Sand Control Completions Supported by Field Case Histories,” SPE 65140 (2000); Tiffin et al., “New Criteria for Gravel and Screen Selection for Sand Control,” SPE 39437 (1998); Wong G. K. et al., “Design, Execution, and Evaluation of Frac and Pack (F&P) Treatments in Unconsolidated Sand Formations in the Gulf of Mexico,” SPE 26563 (1993); T. M. V. Kaiser et al., “Inflow Analysis and Optimization of Slotted Liners,” SPE 80145 (2002); Yula Tang et al., “Performance of Horizontal Wells Completed with Slotted Liners and Perforations,” SPE 65516 (2000); and Graves, W. G., et. Al., “World Oil Mature Oil & Gas Wells Downhole Remediation Handbook,” Gulf Publishing Company (2004).